Look Ahead Advance Formation Evaluation Tool

ABSTRACT

Evaluation which investigates the formation or formation characteristic in advance of the drill-bit before the formation or formation feature of interest has been penetrated or traversed. A closed-loop real-time look-ahead formation evaluation tool which provides acoustic and/or electro-magnetic formation data beyond the drill-bit using a novel angular sensor orientation which also allows for optimized signal propagation and signal returns according to an axial plane and vertical depth.

FIELD OF THE INVENTION

This invention relates to a look-ahead or advance formation evaluationwhile drilling apparatus or tool that is capable of evaluating boreholeand formation characteristics ahead of a drill-bit, directional controlsystem or tubular, especially for use in wellbores in the oil and gasindustry. The apparatus and tool find particular use in characterisingformations and their geo-physical and petro-physical featuresprincipally using ultrasonic means, but can also be configured withelectromagnetic sensors to provide other types of downholecharacterisation.

On average, 65% of hydrocarbons are left underground this equates to arecovery rate of 35%. A look ahead logging tool would potentially helpincrease recovery rates. It is to be understood that the term ‘lookahead’ as used herein refers to the capacity of the invention toevaluate a formation according to a determined angular orientation andthus define a formation or a formation feature within a 3D cone ofinvestigation that extends from the tool at a determined angle andreaches a given axial and true vertical depth ahead of the bit. Incontrast, prior art logging tools are differentiated as behind the bit.The present invention has for a principal object a ‘look ahead’capability to investigate formations ahead of the bit whichdistinguishes it from the prior art. The tool itself can also beconfigured with stabilisation or directional control features such as arotary steerable without necessarily affecting the means ofinvestigation.

Other aspects of the invention include a method of operating a lookaheadapparatus or tool to determine formations ahead of the bit or beforeformations are penetrated and thereby increase hydrocarbon recoveryfactors by optimally placing wellbores; a method of focussing signalorientation angularly, axially and vertically ahead of a drill-bit; amethod of focussing signal propagation angularly, axially and verticallyahead of a drill bit; an optimised sensing zone and use of additionalsources, receivers or transducers housed in a drill-bit in conjunctionwith the apparatus or tool. In a further aspect, the invention relatesto an apparatus for controlling logging and wellbore placement inreal-time.

Although sonic investigation is a principal route to characterizingcertain formations and their features, the invention is not limited toacoustic means. A further embodiment is envisaged with additionalinvestigation means similarly integrated with the look-ahead capabilityof the tool. These additional means can include electro-magnetic wavessuitably combined with acoustic measurements for optimal wellboreplacement. Such a combination would allow acoustic or porositymeasurements to be correlated with resistance or conductivitymeasurements for oil, gas and water zone identification.

When deciding the optimal trajectory and placement of an exploration orproduction well, numerous downhole activities are conducted to ensurethe highest recovery of hydrocarbons and minimise the production ofwater over the well's life-span. Geo-physical data such as formationporosity, permeability, oil, water, gas contact zones, formation bedsand dips are required to be known to steer the well to its optimallocation. A variety of logging-while-drilling technology such as neutrondensity, gamma ray, resistivity and acoustic investigation tools arecommonly used to identify formations and evaluate their features. (FIG.1).

The present invention details an embodiment of a sound based formationevaluation tool which may be configured as a single tool, housing ormodule or several tools, housings or modules as an apparatus optimallylocated along a drill-string to form an improved logging measurementbased on the projection of an acoustic or electro-magnetic signal aheadof the drill-bit, reflected back to a receiver and thereby achieve thepurpose of the invention which is to evaluate a formation before it hasbeen penetrated.

Several types of sound based investigation tools exist such as passiveseismic that record natural seismic events, active seismic that generateand register sound waves from man-made sources and those known asacoustics (below 20,000 Hz) and those known as ultrasonic (above 20,000Hz). It is understood that the term ‘acoustic’ may cover ultrasonic orother frequencies.

Seismic tools provide wide-scale geological data, however these havepoor resolution of formation detail and drilling itself is the true testof geophysical formation characteristics. Therefore, there is a need forand reliance on real-time acoustic while drilling tools. These tools usetransducers or sources to create high frequency sound waves which arepropagated as shear or pressure waves in solids and fluids respectively.Sound waves are further classified as those travelling within thewellbore (Stoneley waves), the near formation as (Flexural waves) andfar formation as (Body waves). Through an evaluation of the echo pulse,its maxima and minima, which are received back by the sensor/receiver,and derivations thereof, calculations, can be made as to the timeinterval between signal transmission and recording the echo to determinethe distance to an object or formation feature. Further, usingalgorithms various characteristics such as formation density, voidspaces, fluid saturations, fluid trapping and formation directionchanges such as beds or dips all have definite signature velocities thatcorrespond to their reflective ability.

In all of these applications, the prior art suffers from two majorlimitations (FIG. 2, 90, 100). Firstly, sensors which may be defined assources and receivers or transducers in any configuration are locatedtoo far behind the bit for timely formation evaluation (100). Thedistances (100 feet [30 metres] or more) between sensors and thedrill-bit restricts formation evaluation to the area nearest the sensorwhich is always in area that has already been penetrated and drilledthrough as it is behind the drill-bit. Second, the orientation of suchsensors and the propagation of their acoustic pulses are lateral (90).This severely limits signal focus to allow for orthogonal investigationonly (FIG. 2). Even where signal propagation is increased due to aplurality of sensor receiver arrays or due to deeper readings, thedistance between such arrays and the drill-bit remains substantiallyunchanged so that formations are only evaluated once they have beendrilled through. In this way, the prior art can only provide forformation evaluation subsequent to drilling. This is unsatisfactory asit prevents the optimal placement of wellbores due to the tardy arrivalof formation data after wellbore placement has already occurred.

Measurement may involve the acquisition and communication to surface ofvarious types of wellbore data such as resistivity, porosity,permeability, azimuth, inclination and borehole diameter or rugosity,formation dips or bedding angles.

Measurement itself occurs in two modes, either wireline orlogging-while-drilling. Wireline is performed as a separate andconsecutive activity to drilling involving the conveyance of measurementtools on a wire or cable. Wireline logging tools generally cannot berotated and are not used in the while-drilling application for thisreason.

Logging-while-drilling tools acquire various data from the wellbore.Acoustic or ultrasonic tools may be incorporated within logging tools.As they can be rotated, such tools may be used while drilling to acquiresonic measurement data. However, they suffer from restrictions inplacement and investigation depth (FIG. 2). Placement is restricted dueto the requirements of the directional control system such as a rotarysteerable or steerable motor which need to be configured near to the bitin order to provide deflection or orientation forces to the bit.Therefore, the location of the acoustic tool is within the BHA above thedirectional control system (FIG. 3). Further, the acoustic tool may beplaced behind other logging tools which are numerous. These includeNeutron Density, Resistivity, Gamma Ray. The cumulative distance of suchlogging tools may exceed 100′ (30 m) behind the drill-bit and such toolscan only give readings after the section has been drilled. Often thesonic tool alone is 36′ (10 m) in length.

Sonic tools harness time-of-flight echo pulses to identify a givenformation or interval transit time, designated ‘∂t’. Each formation hasa sonic velocity or signature that is a measure of a formation's abilityto transmit sound waves. Formation lithology, compressive strengths androck types, notably, porosity or void spaces within the rock matrix havemajor affects on sonic velocities. In porous rocks there is a greaterpercentage of void space containing fluids which alters the sonic traveltimes as compared to a rock that has no void space. Sonic tools in thisway measure travel time and many equations can be solved usingderivatives of travel time and relationships. These include the timeaverage equation which has total travel time dependent on the time thesonic wave spends travelling the solid portion of the rock, called therock matrix and the time spent travelling through the fluids in thehollow portion of the rock, called the pores.

Acoustic or ultrasonic formation measurements rely heavily on thelateral orientation of acoustic sensors. Typically, in an attempt toincrease the depth of investigation as well as create a wider zone ofinvestigation, it is routine for prior art acoustic sensors andreceivers to be placed in consecutive arrays. Irrespective, of thenumber of arrays, this approach does not resolve the problem of what isahead of the bit, as measurements are taken from considerable distancesbehind the drill-bit or after drilling has already finalized thetrajectory of the wellbore.

In the event of a productive hydrocarbon bearing zone having beenbypassed or exited, there is a retrospective time-lag between the databeing received showing where the hydrocarbons are located and thesubsequent correction of wellbore placement. Often, the time-lag leadsto uncertainty, additional cost and can be accompanied by a loss ofproduction as hydrocarbons are bypassed or the optimal heel-to-toeconfiguration within a low permeability zone is lost. In the case ofproductive zones, characterization occurs only after drilling and thearea has been traversed, which means that the payzone of the reservoirmay be exited and further corrective drilling must occur to place thewellbore in the desired payzone. Such cycles of delayed formation dataarrival and subsequent corrections can be eliminated with the presentinvention.

BACKGROUND OF THE INVENTION

Geological mapping and geophysical surveys allow oil companies tocharacterise their acquired acreage and the age and sedimentationpatterns of the rock formation contained therein. This process ofcharacterisation can be reconstructed as a visual earth model thatdelineates the position and shape of the structure including anticlines,faults-stratigraphy, structure which helps increase production fromsubsequent wells and from the field as a whole. However, the earth modeland the well plan have inherent uncertainties.

Geological uncertainties and challenges are related to the location ofthe hydrocarbons, water contacts, traps, formation stresses, movementsand reservoir porosity and permeability. To overcome these challenges, ahighly detailed well plan is developed which contains the wellobjective, coordinates, legal, geological, technical and wellengineering data and calculations. To resolve the uncertainties,however, drilling is the final test.

The data is used to plot a well profile using precise bearings which isdesigned in consecutive telescopic sections—surface, intermediate andreservoir. To deliver the well objective and maintain the integrity ofwell over its lifecycle, a given wellbore trajectory with multiplesections and diameters is drilled from surface. Although there are manyvariants, a simple vertical well design could include a surface ortop-hole diameter of 17½41 (445 mm), intermediate sections of 13⅝″ (360mm) and 9⅝″ (245 mm) narrowing down to the bottom-hole diameter of 8½″(216 mm) in the reservoir section.

Scarcity of oil and gas is driving oil and gas companies to explore anddevelop reserves in more challenging basins such as those inwater-depths exceeding 6,000 ft (1830 m) or below massive salt sections.These wells have highly complex directional trajectories and highlysophisticated formation evaluation requirements. Known in the art as‘3D-designer’ wells, these wells have highly complex trajectories due tothe need to access various reservoirs with a single wellbore as well asthe configuration of the hydrocarbon reservoirs. 3D wells and horizontalwells have created a need to ‘geo-steer’ the wellbore to avoid bypassingproductive reservoir zones and guide the wellbore into the optimalproduction zone. On average, 65% of hydrocarbons are left undergroundthis equates to a recovery rate of 35%. A look ahead logging tool wouldpotentially help increase recovery rates.

Therefore, the bottom-hole assemblies that are needed to drill thesewells routinely include acoustic, sonic or other sound based loggingdevices to characterize formations. In this way, logging is an integralpart of well construction and there is now an increased dependence onlogging for wellbore placement and formation evaluation.

Previously, the ultrasonic and electro-magnetic tool has been restrictedin its placement above the drill-bit and limited to taking lateralmeasurements only. Typically, the distance would be approx 100 feet (30metres) behind the drill-bit, meaning that formation data would beprovided only after a formation had been penetrated or traversed.Consequently, the drill-bit may have exited a payzone and the wellborewould have to be deflected back to the optimal location. If criticalknowledge of the formation i.e. reservoir structures, fractures, beds ordips and fluids contained therein can be gained in advance before beingdrilled through this would lead to greater recovery rates due to moreeffective wellbore placement by increasing the actual drilled footage inthe payzone.

In other applications such as gas zone, kick detection, pore pressureanalysis or fracture identification, the tolerances between the plannedparameters and actual downhole parameters can be very close andvariations of 0.2 ppg (0.02 kg/l) can lead to the failure or loss of thewell. By being able to detect a kick, or establish a fracture before itis actually drilled through, remedial drilling action can be taken inadvance saving time, money and providing a significant safety margin.

Insofar as the prior art is concerned, there are three genericapproaches which have attempted unsatisfactorily to overcome thelimitations of acoustic logging. First, it is routine to move sensorscloser to the borehole to achieve greater lateral proximity or evencreate contact with the wall of the wellbore. Second, to increase thenumber of consecutive source and receiver arrays. Lastly to deflectsignals into the formation. The prior art has not dealt with thefundamental problem of orienting the acoustic source or electro-magneticsignal to look ahead of the bit or reducing the distance to the bit.

The prior art is limited as they depend on measurements perpendicular tothe tool axis, or lateral or orthogonal orientations which cannot seebeyond the tool itself irrespective of longitudinal or angular depths.Further, signal transmission and signal propagation is limited toshallow depths of investigation typically no more than a few feet.Lastly, the positioning of the prior art at significant distances behindthe bit creates further restrictions insofar as the depth ofinvestigation is severely limited to a zone that has already beendrilled. Therefore, drilling has taken place and the wellbore trajectoryhas already been landed. Any such data acquired at this point is afterthe event data and the drilling assumption is always that the currentformation trend or bed should continue. There are no actual measurementswhether direct or inferred until after the bit has penetrated aformation and the logging tools have traversed the said formation.

It is unsatisfactory to depend on source placement or source, receiverplacement that is lateral; orthogonal or perpendicular to the tool axis.Such placements do not provide measurements of the formation beyond thenear wellbore nor do they provide lookahead data; they simply giveinformation on the geological or formations that have already beendrilled and where it is too late to achieve a desired optimal welltrajectory. Hence, there is the constant cycling of directional tools tomaintain wellbore inclination or azimuth.

To those skilled in the art, it is known that the industry relies onbehind the bit data which can be 100 feet (30 metres) or more behind thebit.

Therefore, the prior art does not lend itself to a reliable or certainmeans of look ahead investigating formations during or immediately priorto their drilling.

Further the prior art generates time-consuming correction cycles ofchanges in azimuth and inclination in an attempt to retrospectivelymaintain an optimal well trajectory.

Further, the prior art contributes to an average and unsatisfactoryrecovery rate of 35% of hydrocarbons as reserves are not located in anoptimal manner.

Further the prior art does not detect variations in formations ahead ofthe bit in real-time.

Further the prior art does not detect variations in formationcharacteristics such as porosity or fluid content ahead of the bit inreal-time.

Further the prior art does not detect gas zones, fractures or waterflows ahead of the bit or wellbore in real-time.

Further the prior art does not detect pressure or temperature variationsahead of the bit or wellbore in real-time.

Further the prior art does not automatically allow for a closed-link orautomatic troubleshooting of well trajectory placement.

SUMMARY OF THE INVENTION

The present invention has for a principal object to provide animprovement on the prior art wherein the formation or formationcharacteristic is investigated in advance, that is to say simultaneouslywith, or immediately after, or immediately before drilling commences butat all times ahead of the drill-bit before the formation or formationfeature of interest has been penetrated or traversed.

The present invention optimally orients sources and receivers ortransducers which in addition can be placed much closer to the bit orwithin the bit itself and propagate signals ahead of the bit intoformations that have not yet been penetrated or traversed. Datacommunication may be achieved via a mud-pulsed signal or other wirelesstransmission or wired to ensure it is received at surface in real-timeand wellbore trajectory can be optimized.

The invention seeks to meet the need for a closed-loop real-timelook-ahead formation evaluation tool which provides real time formationdata beyond the drill-bit. This has not been forthcoming in the behindthe bit prior art due to design limitations inherent in the sensorplacement, orientation or distance located from the bit.

The present invention seeks to directly investigate formations ahead ofthe bit and offers optimal wellbore placement using a novelangular/longitudinal source, receiver or transducer orientation whichalso allows for optimized signal propagation and signal returnsaccording to an axial plane and vertical depth.

The present invention eliminates the uncertainty of post drillinginvestigation and eliminates the need for corrective directional runsand consequent wellbore tortuosity by providing real-time data whichallows the driller to respond much earlier to formation characteristicsthereby increasing recovery factors while saving time and money.

It is thus an object of the present invention to provide acousticformation evaluation tools with lookahead means, enabling the device togive immediate evaluation of a formation to be drilled, or thecharacteristics of a formation yet to be drilled and, if the tooldetects a parameter of interest or a change in a parameter of interestsuch as porosity, fault or gas zone, to automatically calculate andcorrect for an optimal well path, and to repeat evaluation until such anoptimal well path result is achieved in real-time.

Although sonic investigation is a principal route to characterizingcertain formations and their features, the invention is not limited toacoustic means and envisages a further embodiment with additionalresistivity investigation means similarly integrated with the look-aheadcapability of the tool. These additional means can includeelectro-magnetic waves suitably combined with acoustic measurements foroptimal wellbore placement. Such a combination would allow acoustic orporosity measurements to be correlated with resistance or conductivitymeasurements for oil, gas and water zone identification.

It is a further object of the present invention to provide a toolcapable of simultaneously looking ahead of the bit, taking sonicinvestigative measurements preferably by an acoustic source and receiveror transducer, and verifying such measurements through a processorarrangement that uses said sonic measurements to detect formationparameters of interest and conducts diagnostics according to a logiccircuit in order to ensure the wellbore path is optimized in view ofinvestigated measurement data. If a parameter of interest is detected,the processor will automatically detect whether corrective steps arerequired to steer/maintain the wellbore in the optimal zone. If the toolfinds a significant azimuthal or inclinational divergence, a signal maybe sent to the rig-surface or to the location of the operating engineerso that further remedial action can be taken, such as coordinaterevisions. A memory mode may store sensor information that can bedownloaded at surface when the tool is retrieved, or sent to the surfaceby telemetry. The tool may also have a built-in link to a mud-pulsetelemetry system to allow real-time monitoring of the formation yet tobe penetrated.

One or more sources and receivers or transducers may be optimally spacedin a forward looking angular or longitudinal orientation in order toemit at least one sound wave ahead of the drill-bit or ahead of adirectional control system or ahead of a tubular during a given timeperiod some of which are reflected back by the formation.

A keyway may provide a channel for wiring from the sensors to theprocessor and transponder. The wiring can be used to transmit acousticdata retrieved by the acoustic sensors, as well as positional andstructural data of formation characteristics and their relative distancefrom the tool and drill-bit. The keyway may be sealed and filled with ameans to absorb vibration such as silicon gel or grease and to maintainwires in position. Similarly, the keyways may be left redundant and as aback-up to a wireless mode of operation.

The transponder converts formation data so that it can be transmittedand is linked to the mud-pulser which transmits the data to surfaceusing a series of binary codes at a given frequency using drilling fluidas means of mud pulsing. Other means of data transfer may be used suchas wireless transmission short hop using radio frequency orelectro-magnetic pulses or wired drill-pipe. This allows up and downlinkof the tool in order to receive and transmit data and commands so as tooptimize wellbore placement before formations are traversed.

At surface a transducer may be incorporated within a decoder housingwhich decodes the binary code and may link to the driller's terminal ormay be yet further transmitted by satellite or other means to a remoteoperations centre.

These and other objects will emerge from the following description andthe appended claims.

In one aspect, the look ahead apparatus (50) comprises at least one toolbody with means for attaching the tool body (63) directly or indirectlyto a drill-bit or support whereby it can be rotated and moved axiallyalong a passage (20), and is characterized by, at least one profiledelement (58) which houses at least one source, receiver or transducerthat is disposed outwardly and projects forwards at an angle of at least0.25° or as much as 89.75° (FIG. 5) relative to the horizontal axis ofthe tool, and (57) is adapted to transmit sound and recognize acousticvelocity signatures from a formation (70) or from a feature of aformation (110,120,130,140) and thereby increase hydrocarbon recoveryrates by optimizing wellbore trajectory based on formation data acquiredby the receiver or transducer before, during or after a drillingoperation occurs but at all times before a formation or formationfeature has been penetrated by the drill-bit (70).

The support may typically be a drill string (30) or an extended lengthof coiled tubing connected via the tool to a drill-bit, as used indownhole operations in oil and gas fields.

In preferred embodiments of the invention, the investigation operationis based on acoustic source, receivers or transducer elements comprisinga set of at least one source, receiver combination or transduceroptimally configured and oriented to send sound waves beyond a drill-bitand receive acoustic velocity signatures. The tool may be directly orindirectly connected to a drill-bit dependent on requirements. Thesource, receiver or transducer housing may comprise protective covering,which may be of similar construction to the source, receiver ortransducer, but having outer surfaces which are protected by a hardenedmaterial. Such protection may simply bear under temperature, pressure orflow acting against it from the inside of a wellbore. In an alternateembodiment, the zone surrounding the housing may be treated to activelyreceive echo pulses rendering it a sensing zone which allows for a amethod of formation evaluation which uses the treated zone to activelysend or receive echo pulses.

The sources, receivers or transducers may be provided with a lenssurface that may be convex (52 a), concave (52 b), or planar (52 c)according to requirement. The sources, receivers and transducers maybeoptimally tuned and gated in terms of frequency so that emittedfrequencies do not cancel out upon contact with return waves and so thatreference measurements are taken to establish background noise whichwould be suitably excluded from operational time-of-flight calculations.Alternatively, the same sources, receivers and transducers may bereceived within an additional section of the tool or a separate steelbody or behind or ahead such section suitably prepared to provide ameans of stabilization or centralization and protection for drillingapplications. Further sources, receivers or transducers may be providedwith a means to reduce ‘ringing’ or ‘dampening’ of the sound waves so asto always ensure the tool is fit-for-purpose.

It is to be noted that the description herein of the structure andoperation of sources, receivers and transducers and tool design isapplicable generally, irrespective of function, except to the extentthat acoustic sources, receivers or transducers may be providedspecifically for formation evaluation purposes and replaced by othersensors such as resistivity sensors as required by the drillingoperation.

The tool body is typically a cylindrical high grade steel housingadapted to form part of a bottom-hole assembly (BHA). Thus the means forattaching the tool body to the support, whether it is a drill string orcoiled tubing, may comprise a screw thread provided on the tool bodywhich is engageable with a drill collar. The attachment to the drillstring need not be direct, but may be indirect, as there will typicallybe many different functional elements to be included in the long andnarrow BHA, and the arrangement of the successive elements may vary. Thelower end of the BHA may be the drill bit which may be directlyconnected to the tool and in between there may or may not be a means fordirectional control such as a rotary steerable system or directionalmotor. The tool body may be provided with a through passage for the flowof drilling fluid from the drill string.

The sources, receivers and transducers may be protected and housed in aplurality of angular depth orientations directed outwardly of a profiledtool body and at all times ahead of the bit. The sources, receivers andtransducers may be received within the profile of the tool body in asource, receiver and transducer recess suitably protected from abrasion,wear and damage by means of at least one protective coating or covering.The protective coating maybe steel with HVOF, tungsten carbide, boronnickel or other protection according to requirements. The source,receiver and transducer may be provided with a dampening material ormechanism such as silicon gel or a spring.

The source and receiver or the transducer may then be provided withmeans for driving the sonic pulses and receiving the echoes from the farformation, near formation or wellbore. The microprocessor control meansmay be suitably adapted to receive formation data from the source,receiver or transducer and to control the frequency in response thereto.A gating procedure may be suitably incorporated to discard a range ofbackground noise frequencies or by means of establishing a maximareference measurement and engaging with such a maxima or by means ofestablishing a measurement and engaging with such a measurement.

Pressure compensation may be provided to handle variations in downholepressure compared to surface atmospheric conditions where activation isopposed by external pressure. This may comprise a port from a source ofdrilling fluid into a chamber suitably connected to the area within thetool requiring pressure compensation (not shown).

The system may comprise a microprocessor means for monitoring formationevaluation data and relative positions of formation structures where themicroprocessor means may include a means of automatically anticipatingany formation or detecting a feature of a formation or detecting achange in the feature of a formation, thereby guiding the directionalcontrol system to ensure the optimal trajectory and placement of thewellbore.

The tool normally comprises a plurality of sources and receiversarranged symmetrically around the tool and disposed outwardly at angularorientations. The source and receiver may be configured as an integraltransducer or separated as a source to receiver. Two transducers wouldbe on opposite sides of the tool, three transducers would be separatedby 120 degrees, four by 90 degrees, and six by 60 degrees. Several toolbodies with sources and receivers could be combined along longitudinalBHA or wellbore spacings, with the object of ensuring the zone of pulsedinvestigation and the zone of echo capture is optimized. In operation,the lookahead apparatus or tool is typically rotated on the drill stringas well as being moved axially along the wellbore.

In accordance with a particularly preferred aspect of the invention, thetransducer or source and receiver array is provided with an internalkeyway for directing power from a source within the tool and providingcommunications to and from the sensor receiver. The source of power maybe a battery within the tool or within another support for the toolsuitably adapted for such purpose. The communications may be a processorwithin the tool, or at surface or other support for the tool suitablyadapted for such purpose. Alternatively or additionally, the source,receiver and transducer or tool body may be provided with a wirelessmeans of communication to an internal or external processor. In eachcase, the two-way communications provide data transmission, operationalrefinement and data capture.

In order to keep the source, receiver or transducer clean and preventthe build-up of clogging debris from the drilling operation, the source,receiver or transducer housing may be provided with specialized coatingto minimize the residence or remove such material altogether from thesource, receiver or transducer.

In one embodiment the present invention incorporates an optimallyoriented and spaced sound based means of formation evaluation which ispractically applicable and may be ultrasonic.

In another embodiment of the acoustic lookahead tool housing for othertypes of sensors such as electro-magnetic is provided within the profilewhich offers a robust and optimal location. This has not been possiblewith previous tools due to their inherent design limitations which relyon orientations which are lateral, orthogonal or perpendicular to thetool axis.

The tool may further comprise telemetry means for communicating downholedata and control signals between the tool and a surface interface, whichmay, among other functions, control the drill string during theformation evaluation operation.

In a further aspect, the invention provides a method of operating alogging apparatus or tool to investigate a formation or parameter ofinterest ahead of a drill-bit or directional tool or the like tooptimally guide and place a wellbore which comprises locating a toolaccording to the invention in a borehole on a support behind adrill-bit, activating the source, receivers or transducers to receivesonic reflections from the formation and establish data on formationsand features thereof, their relative distance, azimuth and size from thetool in a preferred embodiment of a profiled steel tool housing,rotating the tool and moving it axially along the borehole on the drillstring or other support, investigating the formation by the sonic means,and continuing the sonic investigation until an optimal wellboreplacement is achieved.

In accordance with the method of the invention, the tool may be providedwith microprocessor means responsive to formation data received from theacoustic source, receivers or transducers. In this way, a closed looptool which is capable of detecting formation changes and correctingwellbore direction may be realised. The acoustic source, receivers ortransducers may investigate the formation, or investigate a feature of aformation, take reference measurements to establish background noise andmay provide data to a surface monitor to signal an opportunity foroperator intervention to correct wellbore trajectory if it were not ableto do so automatically.

Thus, in the case of the look-ahead tool with acoustic investigationmeans, acoustic reflections from the formation are detected by areceiver or transducer. Sonic waves may be transmitted from the sourceand detected by the receiver (or transmitted and received by thetransducer) calculated as return times based on differing signaturevelocities from the formation ahead of the bit. The processor correlatesthe formation data from the maxima return as well as particularsignatures such as dips, formations, allowing for variations in drillingfluid or the formation. The processor uses this data to correlatewhether the pre-programmed wellbore trajectory is actually being drilledto an optimal well path based on ahead of the bit formation evaluation.Where the processor detects a formation or feature of interest such as afault or change in porosity or a gas zone it automatically correlatesthe two measurements and recalculates an optimal trajectory.

In the case of background noise, the driller may pull the drill-bit offbottom and take a reference survey without drilling which will allow forsubsequent drilling noise to be measured. The difference between the twominimum measurements is automatically employed by the processor asbackground noise or redundant data.

For example, the processor may be programmed with a logic circuit whichcan be configured in any number of ways so as to optimize performance.An exemplary configuration may involve the circuit to first cross checkthe off bottom acoustic data and then take drilling measurements. Inthis way, it can be seen whether there are any changes in the formationor its features. If the maxima return signals show that the formationahead of the bit is a continuation of the present formation, there is atrend that can be followed. If the data ahead of the bit shows, forexample, a change in the dip angle or a formation intersection or gaszone then the tool can alert the user by means of mud pulse telemetry tocheck the trajectory and action such azimuthal or inclination control asnecessary or prompt this through a closed loop directional drillingsystem. The skilled person will readily appreciate that other proceduresmay be implemented by the logic circuit within the processor, which canbe programmed to cover other scenarios.

In another aspect, the invention provides a lookahead apparatuscomprising at least one tool body with at least one set of source andreceivers, optionally but not limited to a housing carrying a pluralityof acoustic sources and receivers or transducers directed outwardly ofthe tool body, wherein the acoustic source or receiver or transducer isreceived within the tool body in a purpose built housing having an openmouth, and means for allowing source acoustic waves to propagate to andfrom the housing and to and from the wellbore, as well as the near andfar formation.

In a still further aspect, the invention provides a lookahead apparatuscomprising at least one tool body with said source, receiver or saidtransducer and a bit body with an acoustic source or receiver ortransducer housing carrying a plurality of source, receiving ortransducers directed outwardly of the bit body, wherein the source orreceiver or transducer or combination thereof is received within the bitbody in a chamber having an open mouth, and means for housing, retainingand propagating the acoustic signal transmission from the chamberthrough the acoustic source or receiver or transducer protection whiledrilling or off bottom and where the acoustic source or receiver ortransducer is provided with an internal keyway open to a source of powerand communications.

Additionally, acoustic source and receiver or transducer arrays may beconfigured optimally by providing longitudinal spacings between theacoustic sources, receivers and transducers.

Additionally or alternatively, other sensor types may replace theacoustic sensor receiver array.

Other aspects of the invention are disclosed in the following specificdescription of exemplary embodiments of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the invention are illustrated by way of non-limitingexamples in the accompanying drawings, in which:

FIG. 1 is a general diagrammatic view of an oil or gas well showing rigsurface structures (10) and the underground well (20), with a tool (50)in accordance with the invention as part of a bottom hole assembly (40)drilling a well (30) and indicating formations and formation features(70) located ahead of the drill-bit (60) and a wellbore (80);

FIG. 2 is a downhole side view illustrating the limitations of prior artbased on their distances behind the bit (100) limiting formationevaluation to those formations behind the bit and in a lateralorientation only (90) and formations (70) and formations features notinvestigated (110, 120, 130, 140);

FIG. 3 is a downhole BHA showing detailed components and distancescorresponding to FIG. 2

FIG. 4 is a 3-D Cube Earth Model from a downhole side view, part cutaway to show the invention's ability to look ahead of the bit (180)according to an angular conical condition and detect formations (110,120, 130) ahead of the bit. FIG. 4 also shows several tool bodies withsources and receivers (50) which can be combined along longitudinal BHAor wellbore spacings, with the object of ensuring the zone of pulsedinvestigation and the zone of echo capture is optimized;

FIG. 5 is a diagrammatic lateral view of the tool part cut away to showsource (51) and receiver (52) elements housed (53), and oriented in anovel angular profile (58) according to an angle (57), of the tool ofFIG. 1;

FIG. 6 is a diagrammatic cross section through a lookahead tool inaccordance with the invention similar to that shown in FIG. 5, buthaving a rotary steerable (62) or other wall contact member (69) at thetrailing uphole end;

FIG. 7 is a diagrammatic cross section through a lookahead tool inaccordance with the invention similar to that shown in FIG. 5, buthaving an additional stabiliser or protective section (61) at theleading downhole end;

FIG. 8 is an enlargement of part of FIG. 5 showing a source (51),receiver (52) and its housing (53), means of power (54), processor (55),hard-wiring (56) and angular orientation (57) within a profile (58) andinternal flow bore (59) and lens surfaces on the sources or transducers(52 a, 52 b, 52 c) with transponder (64) and mud-pulser (64 a); FIG. 8 acorresponds to FIG. 8 wherein a plurality of sources, receivers ortransducers are housed in the said tool body. FIG. 8 b corresponds toFIG. 8 as an alternate embodiment, wherein the zone surrounding thehousing may be treated to actively receive echo pulses rendering it asensing zone which allows for a a method of formation evaluation whichuses the treated zone to actively send or receive echo pulses.

FIG. 9 is an exemplary diagnosis and troubleshooting procedure accordingto the invention showing background noise exclusions and signal gating.

FIG. 10 shows an alternative embodiment with at least one tool body withsources and receivers (FIG. 4, 50) used in association with a drill-bitthat has a source, receiver or transducer to send acoustic waves throughthe formation ahead of the drill-bit itself.

FIG. 11 corresponds to FIG. 10 and shows a secondary tool body withsources and receivers (FIG. 4, 50) used in association with a drill-bitthat has a source, receiver or transducer to send acoustic waves throughthe formation ahead of the drill-bit itself. This secondary tool bodyhas been placed further back from the bit allowing for extendedinvestigation to and from the formations ahead of the bit.

DETAILED DESCRIPTION OF THE INVENTION

As shown in FIG. 1, an exemplary exploration or production rig comprisesa surface structure (10) at the wellhead, a wellbore (20), and a drillstring (30) in the wellbore with a bottom-hole assembly (40) at itslower end. The bottom-hole assembly includes a look ahead drilling tool(50) in accordance with the invention, and a drill-bit (60) andformations yet to be penetrated (70) and the object of the invention.

The look ahead tool (50) is illustrated byway of exemplary embodimentsin FIGS. 4, 5, 6, 7 and 8, comprising at least one tubular steel body(62) provided with a drilling collar pin connection (63) at its downholeend to enable its direct or indirect connection to the drill-bit (60)and a link to a means of communication to the surface (64) at its otherend, which is adapted to be engaged by a further drill collar connection(not shown) to connect it to other elements of the bottom-hole assembly(40), and then to the drill string (35).

The tool body has a profile (58) carrying at least one housing for atleast one acoustic source (51) and a receiver (52) assembly capable oflooking ahead of the drill-bit (60). The source, receiver or transducerassembly (51, 52, and 53) comprises a number of sources, receivers ortransducers disposed symmetrically, radially and at determined anglesaround the profile of the tool body (50) and according to an angularorientation (57) in relation to the horizontal axis of the tool toenable a depth of investigation condition shown in FIG. 4. The saidreceivers or transducers take angular sonic measurements that extendbeyond the drill-bit (60) and well into formations surrounding (70) andahead of the wellbore (110, 120, and 130).

An exemplary configuration of the invention in accordance with itsspecified object is shown in FIG. 5.

FIG. 6 is a diagrammatic cross section through a lookahead tool inaccordance with the invention similar to that shown in FIG. 5, buthaving a rotary steerable (62) or other wall contact member (69) at thetrailing uphole end. Equally, such downhole wall contact maybe a rollerreamer, an expandable under reamer, pressure containment device;

FIG. 7 illustrates diagrammatically the aforementioned elements of thetool (50), together with a stabiliser section (61) in a cross sectionview through a lookahead tool in accordance with the invention similarto that shown in FIG. 5, but having an additional stabiliser orprotective section (61) at the leading downhole end;

As the acoustic source, receiver or transducer is housed in a profiledelement (58), an optimal angle that may be as much 89.5° degrees or aslow as 0.5° degrees is defined (57) as indicated in FIGS. 5, 6, 7 and 8,the tool incorporates an acoustic source (51) and acoustic receiver(52). Tool performance is verified using a micro-processor, shown inlocation (55), which compares data from the source, receiver ortransducer (51,52,53) with a pre-programmed wellbore trajectory, thusdetecting formations and formation features. The tool is also programmedand automated to conduct diagnostics according to a logic circuit ordiagnostic program stored in processor (55) in order to ensure thewellbore is placed optimally. Once corrective steps have been taken, andif the tool indicates that the planned trajectory is not optimal inlight of look ahead data, an alert signal is sent via the transponder(64) and mud-pulser (64 a) to the rig-surface (10) or to a remoteoperator so that azimuthal or inclination control action of the BHA (40)can be taken. A memory module (not shown) associated with processor (55)may store acoustic information that can be downloaded at surface whenthe tool is retrieved, or sent to the surface by telemetry through atransponder (64) and mud-pulser (64 a) or by other communication means.A means of powering the source and receivers or transducers is shown by(54).

The tool is provided with a built-in link to a communication systemwhich may be a mud-pulse telemetry system (64) which also serves tomonitor real-time formation data and features. One or more sources,receivers or transducers (51,52,53) are spaced within the tool bodyprofile (58) in order to emit a number of sound waves during a giventime period which are reflected back by the near wellbore (40) or by thefar formation (110,120,130) in the case of a cavernous formation andpicked up by the acoustic reflection receivers or transducers (52,53).The microprocessor (55) establishes formations (110, 120, 130) andformation features (160) through a series of calculations derived fromacoustic velocity signatures and compare this to preprogrammed ordesired wellbore trajectory. If the two measurements match given userdefined tolerances the tool continues to total depth of the wellboresection. Where the formation data do not match the logic circuitdictates a series of diagnostic steps, which are further discussed inrelation to FIG. 9 below.

As further shown in FIG. 5, a keyway (56) provides a channel for wiring(56) from the acoustic receivers or transducers (51,52,53) to theprocessor (55), and also to a transponder (64) which may be connected toa mud-pulser (64 a). The wiring is used to transmit formation evaluationdata retrieved by the acoustic receivers or transducers (51,52,53) aswell formation features (110, 120, 130, 160) from the receivers ortransducers (52,53) to the processor (55) and transponder (64) and themud-pulser (64 a). The keyway may be sealed and filled with a means toabsorb vibration and maintain wires in position such as silicon gel orgrease (not shown).

The transponder (64) converts data from the microprocessor (55) so thatit can be transmitted to surface (10) and may be linked to themud-pulser (64 a) which transmits the data to surface using a series ofbinary codes at a given frequency using drilling fluid as means of mudpulsation. Other means of data transfer may be used such as wirelesstransmission, short hop using radio frequency to a further mud-pulser orelectro-magnetic pulses.

FIG. 7 shows an alternative configuration with a stabilizing orprotective profile (61) and shows a central axial through passage (59)for the flow of drilling fluid (not shown) through the whole bottom-holeassembly (40).

The acoustic source, receiver or transducer means (51, 52) or integratedtransducer (53), are typically housed within housing (53 a) in the toolbody (50) in a profiled element (58) at an angular outward dispositionof θ (57).

Transducer housing (53) may also be suitably adapted and treated for useof other types of sensor, especially an electro-magnetic sensor toestablish resistivity of formation fluids ahead of the drill-bit (60).In such a case, the power, communications and data processing may beoptimized to suit resistivity applications.

The tool body (50) is a cylindrical high grade steel tube adapted toform part of a bottom-hole assembly (BHA) 40. FIGS. 5, 6 and 7 show adiagrammatic side view of the tool body (50) in embodiments with astand-alone tool (FIG. 5, 50), the lookahead tool configured with arotary-steerable (FIG. 6, 50, 62) and a further tool (FIG. 7 50, 61)configured with a stabilizing or protective element. In FIG. 5, at theleading downhole end there is pin connection (63) to a drill-bit, in thecentre is a profiled section (58) housing sources, receivers ortransducers (51, 52, 53) and control functions (55). In FIG. 6, afurther section (62) at the uphole end, with inclination and directionalcontrol members (69), is connected to the tool or the BHA (40). In FIG.7 at either end of the tool (50) a stabiliser (61) may be placed tostabilize the tool during drilling. Sources, receivers and transducersmay be constructed and housed integrally and generally designated as(51,52,53), except that further numbers of receivers may additionally beplaced surrounding the source to form a sensing zone (FIG. 4, 50). Inthe embodiment of an additional electro-magnetic capability, the sourcesand receivers or transducers generally designated as acoustic may beconstructed and housed integrally to send and receive electro-magneticdata. In all embodiments there is at least one surface which is hardfaced or coated with a hard abrasion-resistant material. The means forattaching the tool body to a drill-bit comprises a pin screw thread (notshown) provided on the tool body which is engageable with a bit box (notshown).

In this alternative configuration the tool is configured, in addition toinvestigative capacity, with the stabilising tool body incorporatinghard facing cutter blocks to act as a stabiliser. The hard facing actsto prevent cutter abrasion while drilling. This eliminates some of theproblems associated with loss of directional control due to anundergauge near bit stabiliser directly behind the drill-bit.

The stabiliser may be directly or indirectly above or below the centralsensing section and may be hard-wired or wireless accordingly so as toensure the mud-pulser (64 a) may transmit data to surface (10). The toolmay be provided with a mud-pulser as a standalone tool or the mud pulseritself may be provided by a third party as would be the case when ameasurement while drilling or logging while drilling suite of tools islocated in the BHA below the present invention. The hard wiringconfiguration of the tool may be changed to suit such an application.

FIG. 8 a corresponds to FIG. 8 wherein a plurality of sources, receiversor transducers are housed in the said tool body. FIG. 8 b corresponds toFIG. 8 as an alternate embodiment, wherein the zone surrounding thehousing may be treated to actively receive echo pulses rendering it asensing zone which allows for a a method of formation evaluation whichuses the treated zone to actively send or receive echo pulses.

As shown in FIGS. 4, 5, 6, 7, 8 and 9, the illustrated example of a toolin accordance with the invention is a lookahead formation evaluationtool which uses a microprocessor (55) and electronic means to determinean optimal wellbore trajectory. Source, receiver or transducer means(51, 52, 53) determine the actual formation characteristics (110, 120,130, 160) and send corresponding signals back to the processor (55).

As required, the sources, receivers or transducers (51, 52,53) may beprotected and housed (53) in a plurality of angular forward orientations(57) directed outwardly of a profiled tool body (58) and at all timesahead of the bit (60) and determined as an optimal orientation based onformation and BHA component considerations. The sources, receivers ortransducers may be received within the profile of the tool body in asource, receiver or transducer housing recess (53) that is also suitablyprotected from abrasion, wear and damage by means of at least oneprotective coating or covering. The protective coating maybe steel witha HVOF coating, tungsten carbide, boron nickel, titanium, epoxy, kevlaror other protection suited to requirements. The sensor may also beprovided with a dampening material or mechanism such as silicon gel or aspring (not shown).

The source and receiver or transducer may then be provided with means(54) for driving the sonic pulses and receiving the echoes from the farformation (110,120,130,160), near formation or wellbore (80). Themicroprocessor control means (55) may be suitably adapted to receiveformation data from the sensors (51, 52) and to control the frequency inresponse thereto. A gating procedure may be suitably incorporated todiscard a range of background noise frequencies or by means ofestablishing a maxima reference measurement and engaging with such amaxima, or by means of establishing any other acoustic velocitysignature.

FIG. 10 shows an alternative embodiment wherein the apparatus comprisesat least three two bodies and at least one tool body is configured withsources and receivers (51, 52) which are used in association with adrill-bit (60) that has a source, receiver or transducer to send orreceive acoustic waves through the formation ahead of the drill-bititself to be further received by one of the said tool bodies. Thisallows for greater flexibility of placement and lower angles ofinvestigation to and from the formations ahead of the bit can be probedand such data can be processed by the micro-processor and communicationswithin said tool body.

FIG. 11 corresponds to FIG. 10 and shows said apparatus wherein asecondary tool body with sources and receivers (FIG. 4, 50) is used inassociation with a drill-bit that has a source, receiver or transducerto send acoustic waves through the formation ahead of the drill-bititself. This secondary tool body has been placed further back from thebit allowing for extended investigation. It can be seen from theseembodiments that many configurations are possible and remain within thepurpose and scope of the invention which is to at all times look aheadof the bit and obtain data on formations or formation features beforethe bit has penetrated said formations.

Pressure compensation may be provided to handle variations in downholepressure compared to surface atmospheric conditions where activation isopposed by a source of external pressure. This may comprise a port froma source of drilling fluid into a chamber suitably connected to the areawithin the tool requiring pressure compensation (not shown).

The system may comprise a microprocessor means for monitoring formationevaluation data and relative positions of formation structures where themicroprocessor means may include a means of automatically anticipatingany formation or detecting a feature of a formation or detecting achange in the feature of a formation, thereby guiding the directionalcontrol system to ensure the optimal trajectory and placement of thewellbore.

The tool normally comprises a plurality of sources and receiversarranged symmetrically around the tool and disposed outwardly at angularorientations. The source and receiver may be configured as an integraltransducer or separated as a source and several receivers known as a‘sensing zone’. Two transducers would be on opposite sides of the tool,three transducers would be separated by 120 degrees, four by 90 degrees,and six by 60 degrees. A number of tool bodies housing said source andreceivers could be configured in a plurality of combinations with theobject of ensuring the zone of pulsed investigation and the zone of echocapture is optimized. In operation, the lookahead tool is typicallyrotated on the drill string as well as being moved axially along thewellbore.

In accordance with a particularly preferred aspect of the invention, thetransducer or source and receiver array is provided with an internalkeyway for directing power from a source within the tool and providingcommunications to and from the sensor receiver. The source of power maybe a battery within the tool or within other support for the toolsuitably adapted for such purpose. The communications may be a processorwithin the tool, or at surface or other support for the tool suitablyadapted for such purpose. Alternatively or additionally, the source andreceiver or transducer or tool body may be provided with a wirelessmeans of communication to an internal or external processor. In eachcase, the two-way communications provide data transmission, operationalrefinement and data capture.

In order to keep the source, receiver or transducer clean and preventthe build-up of clogging debris from the drilling operation, the sensorhousing may be provided with a specialized coating to minimize theresidence or remove such material altogether.

In one preferred aspect the present invention incorporates an optimallyoriented and spaced sound based means of formation evaluation which ispractically applicable and may be ultrasonic.

In another aspect of the present invention housing for other types ofsensors is provided within the profile which offers a robust and optimallocation. This has not been possible with previous tools due to theirinherent design limitations which rely on orientations that are lateral,orthogonal or perpendicular to the tool axis.

The tool may further comprise telemetry means for communicating downholedata and control signals between the tool and a surface interface, whichmay, among other functions, control the drill string during theformation evaluation operation.

In a further aspect, the invention provides a method of operating alogging tool to investigate a formation or parameter of interest aheadof a drill-bit or directional tool or the like to optimally guide andplace a wellbore which comprises locating a tool according to theinvention in a borehole on a support behind a drill-bit, activating thesource or receivers or transducers to emit and receive sound wavesaccordingly from the formation and establish data on formations andfeatures thereof, their relative distance, azimuth and size from thetool in a preferred embodiment of a profiled steel tool housing,rotating the tool and moving it axially along the borehole on the drillstring or other support, investigating the formation by the acousticsensor or receiver or transducer, and continuing the acoustic velocityinvestigation until an optimal wellbore placement is achieved.

To those skilled in the art, it is known that the wellhead surfacestructure (10) includes a control and communications system having aninterface for communication telemetry with downhole instrumentationincluding a transponder and a decoder which decodes data and may belinked directly to the user or driller's terminal. The decoded data maybe yet further transmitted by satellite or other means to a remote useror a remote operations centre by means of a telecommunication link. Thissurface control system allows full communication to and from thedownlink and uplink to the invention.

As noted above, the invention provides a method of automaticallyoperating a directional tool according to a processor which detectsdifferences between programmed and actual measurements using dataacquired from ahead of the bit.

It is recognized that the tool could be programmed by the skilled personto cover many other scenarios.

Those skilled in the art will appreciate that the examples of theinvention given by the specific illustrated and described embodimentsshow a novel lookahead tool and system and method for formationevaluation ahead of the bit, with numerous variations being possible.These embodiments are not intended to be limiting with respect to thescope of the invention. Substitutions, alterations and modifications notlimited to the variations suggested herein may be made to the disclosedembodiments while remaining within the ambit of the invention.

I claim:
 1. A look ahead tool comprising a tool body with means for attaching the tool body directly or indirectly to a drill-bit permitting rotation and axial movement along a well passage comprising: at least one acoustic source, receiver or transducer directed outwardly of the tool body, wherein the acoustic source and receiver or transducer is received within the tool body in a purpose built housing and oriented at an angle that is within the range of about 0.25° to about 89.5° relative to a longitudinal axis of the tool body to send and receive acoustic waves.
 2. A tool as claimed in 1 wherein an electro-magnetic source and said receiver or integrated transducer send and receive electro-magnetic data to and from the formation ahead of a drill-bit, and said data is processed by said microprocessor.
 3. A tool as claimed in claim 1 wherein said tool body is configured with a rotary steerable system with a wall contact member at an end.
 4. A tool as claimed in claim 1 wherein the said tool body includes a downhole wall contact member to form one of a roller reamer, an expandable underreamer, a pressure containment device, and a measurement device.
 5. A tool as claimed in claim 2, further comprising communication means for communicating said acoustic data or electro-magnetic and control signals between said tool and a surface decoder.
 6. A tool as claimed in claim 1 further comprising: a first tool body to investigate a formation ahead of the drill-bit, and a second tool body to stabilize the tool during drilling.
 7. A tool as claimed in claim 4 further comprising: a microprocessor controller adapted to receive acoustic data and detect a formation or formation feature and control an underreamer in response to acquired acoustic data.
 8. A tool as claimed in claim 2 further comprising: a microprocessor controller adapted to receive data based on electro-magnetic data and detect a formation or formation feature and control an underreamer. A tool as claimed in claim 1, wherein said tool body is provided with an internal keyway leading to a source of power communications inside or outside the tool and capable of sending an alert signal to a user.
 9. A tool as claimed in claim 1 further comprising: a plurality of said sources, said receivers or said transducers directed outwardly of said tool body or separately housed and placed along the drill-string in separate tool bodies.
 10. A tool as claimed in claim 9 wherein the means for attaching the tool body to the support comprises a screw thread on the tool body to engage the drill bit, a directional control system, drill collar, underreamer or roller reamer.
 11. A tool as claim 9 further comprising: communication means for communicating said acoustic data or electromagnetic and control signals with the microprocessor, and a surface decoder and user interface in real-time to optimize performance.
 12. A tool as claimed in claim 1 wherein one of another acoustic source and another receiver or transducer is housed in a drill-bit to look ahead and evaluate a formation as yet undrilled.
 13. A tool as claim 2 further comprising: communication means for communicating said acoustic data or electromagnetic and control signals with the microprocessor, and a surface decoder and user interface in real-time to optimize performance.
 14. A tool as claimed in claim 1 wherein said source waves are propagated into the housing, into the wellbore, the near and far formation and can be detected as said received acoustic waves.
 15. A tool as claimed in claim 2 wherein said source waves are propagated into the housing, into the wellbore, the near and far formation and can be detected as said received acoustic waves.
 16. A tool as claimed in claim 1 wherein the source is located in the drill bit.
 17. A tool as claimed in claim 4 further comprising: a plurality of said sources, said receivers or said transducers directed outwardly of said tool body or separately housed and placed along the drill-string in separate tool bodies.
 18. A tool as claimed in claim 1 further comprising: a plurality of said wall contact members separately housed and placed along the drill-string in separate tool bodies. 